Well ranging apparatus, systems, and methods

ABSTRACT

A series of electromagnetic field strength measurements is acquired from a sensor at multiple depths in a first well, responsive to an electromagnetic field originating at a second well, via at least one of a direct transmission and a backscatter transmission. A drilling phase associated with drilling operations conducted in the first well is determined. A sensor separation depth associated with the drilling phase is selected. An approximate range between the first well and the second well is calculated, based on the series of electromagnetic field strength measurements and the sensor separation depth.

BACKGROUND

With much of the world's easily obtainable oil having already beenproduced, new techniques are being developed to extract less accessiblehydrocarbons. These techniques often involve drilling a borehole inclose proximity to one or more existing wells. Examples of directeddrilling near an existing well include well intersection for blowoutcontrol, multiple wells drilled from an offshore platform, and closelyspaced wells for geothermal energy recovery. Another such technique issteam-assisted gravity drainage (SAGD) that uses a pair ofvertically-spaced, horizontal wells constructed along a substantiallyparallel path, often less than ten meters apart. Careful control of thespacing contributes to the effectiveness of the SAGD technique.

One way to construct a borehole in close proximity to an existing wellis “active ranging” or “access-dependent ranging” in which anelectromagnetic source is located in the existing well and monitored viasensors on the drill string in the well under construction. Anothertechnique involves systems that locate both the source and the sensor(s)on the drill string—relying on backscatter transmission from the targetwell to determine the range between the drilling well and the targetwell. These latter systems are sometimes called “passive ranging” or“access-independent” systems by those of ordinary skill in the art. Ineither case, the ranging techniques are sometimes limited in the degreeof accuracy that can be obtained.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 depicts an example drilling environment in which rangingembodiments may be employed.

FIG. 2 is a block diagram of a well ranging system, according to variousembodiments.

FIGS. 3 to 5 illustrate a variety of apparatus, method, and systemconfigurations for various range determination embodiments.

FIG. 6 is a flow diagram of a well ranging method, according to variousembodiments.

FIG. 7 is a block diagram of a wireline system implementation, accordingto various embodiments.

FIG. 8 is a block diagram of a drilling system implementation, accordingto various embodiments.

DETAILED DESCRIPTION Introduction

Magnetic ranging has been widely used for various applications,including well intersection, well avoidance, SAGD, and others. Oneexcitation method for magnetic ranging is surface excitation. Surfaceexcitation is a popular method of generating a ranging signal. It isrelatively easy to implement, without the need for complex cabling andequipment. When surface excitation is used, a current is injected into atarget well casing at the surface of the well (e.g., at the well head).The current travels along the casing down-hole and generates a magneticfield down-hole that originates from the target via direct transmission,and can be measured at a distance (e.g., in a drilling well) for rangingpurposes. As a result, the excitation signal down-hole may be relativelyweak when the distance beneath the surface is great, due to the currentleakage into the conductive formation. Consequently, sensor noise oftenaffects magnetic ranging accuracy at greater depths, leading to falsesignal measurements and failures in well location. Some of theembodiments described herein are designed to improve down-hole currentstrength and/or enhance the signal/noise ratio, for improved accuracywith respect to ranging measurement technology.

Such apparatus, methods, and systems can be even more useful whenbackscatter ranging is used: that is, when the excitation source isinjected into the casing of the drilling well, or is attached to a drillstring within the drilling well. In the case of backscatter ranging, theexcitation source originates a direct transmission signal that impingesupon, and is then reflected from, the target well. When thesebackscatter transmission signals are received at a receiver in thedrilling well, the resulting received ranging signals are even weakerthan in the direct transmission case.

Thus, novel apparatus, methods, and systems are proposed to increase thestrength of the received ranging signal, to improve the receivedsignal-to-noise ratio (SNR), and to improve the accuracy of rangingsignal measurements. In some embodiments, enhancements are realized inall three of these areas. By taking this approach, ranging systemtechnology can be improved in a number of ways, via improved accuracyand reliability of individual ranging measurements. Therefore, theapparatus, methods, and systems proposed herein can be used to reducemeasurement issues that arise due to noise, as well as to generatelarger signals at great depths. The result is that the maximum detectionranges for existing ranging systems can be significantly improved. Insome embodiments, the apparatus, methods, and systems described hereincan be applied to electromagnetic (EM) telemetry applications.

FIG. 1 depicts an example drilling environment 100 in which rangingembodiments may be employed. The disclosed apparatus (e.g., loggingtools), systems, and methods are best understood in the context of thelarger systems in which they operate. Accordingly, FIG. 1 illustrates anexample drilling environment 100 in which a drilling platform 102supports a derrick 104 having a traveling block 106 for raising andlowering a drill string 108. A top drive 110 supports and rotates thedrill string 108 as it is lowered through the well-head 112. A drill bit114 is driven by a downhole motor and/or rotation of the drill string108. As the drill bit 114 rotates, it creates a borehole 116 that passesthrough various formations F. A pump 118 circulates drilling fluidthrough a feed pipe 120 to top drive 110, downhole through the interiorof drill string 108, through orifices in drill bit 114, back to thesurface via the annulus around drill string 108, and into a retentionpit 122. The drilling fluid transports cuttings from the borehole intothe retention pit 122 and aids in maintaining the borehole integrity.

The drill bit 114 is just one piece of a bottom-hole assembly (BHA) thatincludes one or more drill collars (comprising thick-walled steel pipe)to provide weight and rigidity to aid the drilling process. Some ofthese drill collars include logging instruments to gather measurementsof various drilling parameters such as position, orientation,weight-on-bit, borehole diameter, etc. The tool orientation may bespecified in terms of a tool face angle (also known as rotational orazimuthal orientation), an inclination angle (the slope), and a compassdirection, each of which can be derived from measurements made bymagnetometers, inclinometers, and/or accelerometers, though other sensortypes such as gyroscopes may also be used. In one specific embodiment,the tool includes a three-axis fluxgate magnetometer and a three-axisaccelerometer. As is known in the art, the combination of these twosensor systems enables the measurement of the tool face angle,inclination angle, and compass direction. In some embodiments, the toolface and hole inclination angles are calculated from the accelerometersensor output, and the magnetometer sensor outputs are used to calculatethe compass direction.

The BHA further includes a ranging tool 124 to receive signals fromcurrent injected by a power supply 148 into nearby conductors such aspipes, casing strings, and conductive formations and to collectmeasurements of the resulting field to determine distance and direction.Using measurements of these signals, in combination with the toolorientation measurements, the driller can, for example, steer the drillbit 114 along a desired path in the drilling well 126 relative to theexisting well (e.g., target well) 128 in formation F using any one ofvarious suitable directional drilling systems, including steering vanes,a “bent sub”, and a rotary steerable system. For precision steering, thesteering vanes may be the most useful steering mechanism. The steeringmechanism can be controlled from the Earth's surface, or downhole, witha downhole controller programmed to follow the existing borehole 128 ata predetermined distance 130 and position (e.g., directly above or belowthe existing borehole).

The ranging tool 124 may comprise one or more elements, interchangeablydesignated as receivers or sensors in this document. These elements maycomprise uniaxial, biaxial, or triaxial magnetometers, coil antennas,and/or telemetry receivers.

A telemetry sub 132 coupled to the downhole tools (including rangingtool 124) transmits telemetry data to the surface via mud pulsetelemetry. A transmitter in the telemetry sub 132 modulates a resistanceto drilling fluid flow to generate pressure pulses that propagate alongthe fluid stream at the speed of sound to the surface. One or morepressure transducers 134 convert the pressure signal into electricalsignal(s) for a signal digitizer 136. Note that other forms of telemetryexist and may be used to communicate signals from downhole to thedigitizer. Such telemetry may include acoustic telemetry,electromagnetic telemetry, or telemetry via wired drill pipe.

The digitizer 136 supplies a digital form of the telemetry signals via acommunications link 138 to a computer 140 or some other form of a dataprocessing device. The computer 140 operates in accordance with software(which may be stored on non-transitory information storage media 142)and user input provided via an input device 144 to process and decodethe received signals. The resulting telemetry data may be furtheranalyzed and processed by the computer 140 to generate a display ofuseful information on a computer monitor 146 or some other form of adisplay device. For example, a driller could employ this system toobtain and monitor drilling parameters, formation properties, and thepath of the borehole relative to the existing borehole 128 and anydetected formation boundaries. A downlink channel can then be used totransmit steering commands from the surface to the BHA. In someembodiments, the computer 140 has analog circuitry installed or isprogrammed to include a ranging determination module RD, which operateson the signal data received down hole at the ranging tool 124 todetermine the distance and direction from the drilling well 126 to thetarget well 128. The ranging determination module RD may exist in thecomputer 140 or the tool 124, and may be used to implement any of themethods described herein.

Thus, FIG. 1 illustrates an electromagnetic ranging system with surfaceexcitation. The power supply 148 at the surface employs a cable 150 toinject current into target well casing 152 and flowing down-hole so thatmagnetic fields can be generated surrounding a target well 128. Thensensors in the ranging tool 124 in the drilling well 126 can determinethe magnetic field strength in various directions so that distance anddirection between the target well 128 and drilling well 126 can bedetermined. The power supply 148 can also be connected to inject currentinto the casing of the drilling well 126.

The drilling well 126 and the target well 128 are often constructed as acased hole, with cement installed around the outside of the casingmaterial (e.g., conductive piping). In the completion phase of oil andgas wells, the cement serves to isolate the wellbore, helps preventcasing failure, and keeps the wellbore fluids from contaminatingfreshwater aquifers.

To obtain gradient measurements at each depth in the drilled well, twosensors separated in the radial direction (with respect to the targetwell location) are often used. The difference in measurement valuesbetween these sensors gives a measurement of the field strengthgradient. Because the separation distance between the sensors isrelatively small with respect to the ranging distance between the wells,especially when “T” intersection applications arise, the difference infield measurements between the two sensors is often very small. Thus, itis difficult to determine the true gradient measurement using thisconventional system.

As a solution to this technical problem, directional tool measurements,including ranging applications, are used to enable pseudo-gradient fieldcalculations for “T” intersection ranging applications (e.g., wellavoidance or well intersection). A pseudo-gradient field is a field thatis determined by measuring field strength at different depths, ratherthan at a single depth. Separating sensors in the vertical direction ofthe well, rather than in the horizontal or azimuthal direction, canprovide a more accurate measurement of the gradient field because thereis a larger relative separation between measured values. The result ofimplementing the apparatus, systems, and methods described herein maythus be improved accuracy when determining the range between wells atgreater depths. Sensor noise effects on ranging performance may also bereduced. Various embodiments that have been developed to provide some ofthese advantages will now be described.

Detailed Presentation

In well Intersection/well avoidance applications, gradient measurementshave been used to determine the relative distance between a target welland a drilling well. However, it can be challenging to detect thelocation of the target well at great depths. This is because theavailable gradient field measurements are small, due to sensor spacelimitations on the BHA. Therefore, sensor noise and other artifacts willaffect the ranging accuracy at greater depths.

The apparatus, methods, and systems described herein use field strengthintensity measurements of magnetometers at a variety of depths togenerate pseudo-gradient measurements, to improve the ranging accuracyto a target well at greater depths. Owing to larger sensor separationfor these pseudo-gradient measurements, the measurements have bettercapabilities in the presence of noise, as compared to regular gradientmeasurements made from two sensors at same depth in the well.

For example, FIG. 2 is a block diagram of a well ranging system 200,according to various embodiments. Here the drilling well is non-parallelto the target well, and the drilling well is being drilled to eitherintercept the target well, or to avoid interception. Since thedifference in depth for each field strength measurement is known,measurements by a single sensor S2, separated by some depth SD, can betreated as measurements from two different sensors that make independentmeasurements. This method of operation effectively increases theseparation between measurement locations, improving the accuracy of thegradient calculation, which in turn improves the accuracy of the rangedetermination. The separation depth SD can be adjusted, based on theexpected range R to the target well. Thus, if the target well is faraway, the vertical measurement separation can be greater (with lessmeasurement resolution), or if the target well moves closer as a resultof the drilling activity, the separation depth SD can be reduced, toincrease measurement resolution. All three measured field components(e.g., normal N, tangential T, and azimuthal z) can be used to determinethe range R.

FIGS. 3 to 5 illustrate a variety of apparatus, method, and systemconfigurations for various range determination embodiments. In FIG. 3,an infinite line source 300 with a constant current I can be seen. Basedon Ampere's law, the magnetic field H at low frequency surrounding theline source, and shown in perspective view, is expressed as:

$\begin{matrix}{{\overset{\rightharpoonup}{H} = {\frac{I}{2\pi \; r}\overset{\Cap}{\Phi}}},} & (1)\end{matrix}$

where r is the distance between an observation point and the infiniteline source. In addition, the gradient field can be obtained by

$\begin{matrix}{\frac{\partial\overset{\rightharpoonup}{H}}{\partial r} = {{- \frac{I}{2\pi \; r^{2}}}{\overset{\Cap}{\Phi}.}}} & (2)\end{matrix}$

Consequently, the distance r can be directly computed by taking ratio ofthe amplitude of Equation (1) to the amplitude of Equation (2), as givenby

$\begin{matrix}{{\frac{\overset{\rightharpoonup}{H}}{\frac{\partial\overset{\rightharpoonup}{H}}{\partial r}}} = {{\frac{\frac{I}{2\pi \; r}}{\frac{- I}{2\pi \; r^{2}}}} = {r.}}} & (3)\end{matrix}$

Equation (3) is the conventional gradient method used to compute rangingdistance r (equivalent to the range R in FIG. 2).

In practice, two sensors (e.g., magnetometers) are used to obtainmagnetic field and gradient field measurements as shown in FIG. 4, whichpresents a top view of an infinite line source 400 and a logging tool410 equipped with two sensors S1, S2 for gradient field determination. Afinite difference method is then utilized to calculate the magneticfield strength H and the gradient field strength, as given by:

$\begin{matrix}{{\overset{\rightharpoonup}{H} = \frac{{\overset{\rightharpoonup}{H}}_{1} + {\overset{\rightharpoonup}{H}}_{2}}{2}},{and}} & \left( {4a} \right) \\{{\frac{\partial\overset{\rightharpoonup}{H}}{\partial r} = \frac{{\overset{\rightharpoonup}{H}}_{1} - {\overset{\rightharpoonup}{H}}_{2}}{2\Delta \; S}},} & \left( {4b} \right)\end{matrix}$

where H₁ and H₂ are the total field measurements at sensors S1 and S2,respectively. ΔS is the separation distance between one of the twosensors, and the location of a mid-point between the two sensors.Consequently, Equation (3) can be modified based on the finitedifference method to compute the ranging distance r as follows:

$\begin{matrix}{r = {{\frac{\frac{{\overset{\rightharpoonup}{H}}_{1} + {\overset{\rightharpoonup}{H}}_{2}}{2}}{\frac{{\overset{\rightharpoonup}{H}}_{1} - {\overset{\rightharpoonup}{H}}_{2}}{2\Delta \; S}}}.}} & (5)\end{matrix}$

For a given ranging distance r, Equation (5) reveals that as theseparation distance ΔS increases, so does the field difference betweensensors S1 and S2. Consequently, the gradient field given by Equation(4b) will have improved anti-noise capability, extended the detectionrange to greater depths.

To achieve a greater sensor separation distance, the two sensors S1, S2in FIG. 4 can be located farther apart on the tool, as part of the BHA.Or a single sensor S2 can be used to take two measurements at twodifferent depths in the well, to implement the gradient calculationsshown in Equations (4) and (5), as shown in FIG. 2, where H₁ representsthe measurements at a first depth and H₂ represents the measurements ata second depth. The first depth and the second depth can be controlledbased on the desired separation distance ΔS, which will be theseparation between one of the two depths and the center of the twodepths (e.g., 2ΔS may be the separation between the two depths, which isequivalent to the separation distance SD).

On the other hand, the gradient field approximation based on a finitedifference method at Equation (4) may not yield the accuracy desiredwhen the separation distance ΔS becomes large with respect to the range.Consequently, there is a trade-off between improved anti-noisecapability, and approximation accuracy in choosing the separation ofpseudo-gradient measurement locations.

In some embodiments, well-intersection and well-avoidance operations aredivided into three phases: identify, follow, and intercept/avoid. Theidentify phase occurs at the greatest distance from the target well(e.g., at a ranging distance r=about 40 m-100 m) and the need foraccuracy is not as great; sensors may locate the target well positionwith less accuracy. After a rough determination of the target welllocation is made, the follow phase ensues.

In the follow phase, which occurs at a ranging distance of about r=20 mto about 40 m, the desired drilling path is defined, based on the likelytarget well location. Thus, at this point, an improved ranging accuracyis desired; with more resolution than was used for the identify phase.After the drilling path is defined in the follow phase, theintercept/avoid phase begins.

In this final phase, where the ranging distance is usually less thanr=20 m, a decision is made to intercept the target well, or to avoid thetarget well. At this point, a smaller separation of sensors is useful tomeet increased accuracy requirements.

To balance requirements in the different phases, the sensor separationis chosen with respect to the phase in operation, and the accuracydesired. Thus, when the drilling well is far away from the target well(e.g., more than 50 m), a large sensor separation, such as 5 m ofseparation, can be chosen for improved detection ranging at greaterdepths. That is, when the range is relatively large, the rangingaccuracy can be low. Once the follow phase begins, sensor separation maybe reduced to 2.5 m to increase the ranging accuracy. And once theintercept/avoid phase operations begin, sensor separation may be reducedto 0.5 m for even greater ranging accuracy.

FIG. 5 presents a graph 500 that compares ranging performance when usinga conventional gradient sensor design (e.g., where two sensors areinstalled on the same BHA, and both are used to make rangingmeasurements, relying on the separation distance between the sensors onthe BHA to provide a difference in measurement values) and the proposedpseudo-gradient mechanism described herein, where random noise of ±100pT is added to all measurements. Here the range for the actual path 310followed by the target well, versus the path 320 indicated bymeasurements using the regular (conventional) method 320, and the path330 indicated when using the balanced depth separation method togenerate a pseudo-gradient, can be seen.

For the regular (conventional) design, two sensors are used, with afixed BHA spacing of about 0.1 m between them, whereas the designutilizing only one sensor to take measurements at different depths, asproposed herein, makes use of a balanced spacing technique (5 m, 2.5 m,and 0.5 m, depending on the drilling phase) to provide apseudo-gradient. As shown in the figure, the pseudo-gradient path 330follows the actual path 310 of the target well fairly closely. Theregular gradient method 320 does not reliably locate the target welluntil the ranging distance is less than about 40 m. However, thepseudo-gradient mechanism 330 is able to determine the target welllocation at much greater distances, even with the injection of noise.

FIG. 6 is a flow diagram of a well ranging method 600, according tovarious embodiments. To begin generating a pseudo-gradient, sensormeasurements at different depths are recorded and accumulated at block640. These can be passed to a processing unit, such as a RangeDetermination Module RD which may be located down hole, or at thesurface.

The processing unit can be used to determine which drilling phase is ineffect at the current sensor depth (or bit depth) at block 645. Thesephases may include the identify, follow, and intercept/avoid phases, asnoted previously.

Then, the processing unit can be used to choose a suitable sensorseparation from the available accumulated sensor measurements at block650. Three criteria can be used to select the desired sensor separation,including: (1) the sensor noise level, (2) the desired detection range,and (3) the desired ranging accuracy. The sensor noise level can beprovided based on lab noise testing or can be determined in real-timefrom background measurements, as is known to those of ordinary skill inthe art. The desired range for detection, as well as the accuracy forrange determination, are determined using customer requirements, orvalues corresponding to the different drilling phases (e.g., identify,follow, intercept/avoid).

Once a suitable separation distance is chosen at block 650, andsufficient measurements are obtained from the sensor(s), the rangingdistance will be calculated at block 655. Finally, a ranging solutioncan be provided for different drilling phases at block 660.

Additional Detailed Description and Some Representative Embodiments

FIG. 7 is a block diagram of a wireline system 700 implementation ofvarious embodiments. The system 700 of FIG. 7 may include any of theembodiments of receiver or sensor mounting discussed previously. In thiscase, a hoist 706 may be included as a portion of a platform 702, suchas coupled to a derrick 704, and used to raise or lower equipment suchas a wireline sonde 710 into or out of a borehole. The wireline sonde710 may include any one or more of the above-described embodiments,including sensors and a range determination module RD.

In this wireline example, a cable 742 may provide a communicativecoupling between a logging facility 744 (e.g., including a processorcircuit 745 including memory or other storage or control circuitry) andthe sonde 710. In this manner, information about the formation 718 maybe obtained. The processor circuit 745 can be configured to access andexecute instructions stored in a memory to implement any of the methodsdescribed herein (e.g., by accessing a range determination module RD).

FIG. 8 is a block diagram of a drilling system implementation of variousembodiments. This diagram shows a drilling rig system 800 according tovarious embodiments that may include measurement while drilling (MWD) orlogging while drilling (LWD) capability. The drilling apparatus can usedata from a tool or housing in the drill string 808, having attached toa number of receivers or sensors (e.g., including sensors S1, S2) asdiscussed previously, and using acquired and calculated ranginginformation to steer the drill bit 814.

A drilling rig or platform 702 generally includes a derrick 704 or othersupporting structure, such as including or coupled to a hoist 706. Thehoist 706 may be used for raising or lowering equipment or otherapparatus such as drill string 808. The drill string 808 may access aborehole 816, such as through a well head 712. The lower end of thedrill string 808 may include various apparatus, such as a drill bit 814,such as to provide the borehole 816.

A drilling fluid or “mud” may be circulated in the annular region aroundthe drill bit 814 or elsewhere, such as provided to the borehole 816through a supply pipe 822, circulated by a pump 820, and returning tothe surface to be captured in a retention pit 824 or sump. Various subsor tool assemblies may be located along the drill string 808, such as abottom hole assembly (BHA) 826 or a second sub 828. The BHA 826 and/orthe sub 828 may include one or more sensors or receivers (e.g.,including sensors S1, S2), as described herein, along with a currentsource (e.g., power supply 148) to initiate a ranging signal, and aprocessor with access to a memory that contains a program to implementany of the methods described herein (e.g., a ranging determinationmodule RD).

Thus, some of the embodiments described herein may be realized in part,as a set of instructions on a computer readable medium 142 comprisingROM, RAM, CD, DVD, hard drive, flash memory device, or any othercomputer readable medium, now known or unknown, that when executedcauses a computing system, such as computer as illustrated in FIG. 1 orsome other form of a data processing device 140, to implement portionsof a method of the present disclosure, for example the processes andmethods described in FIG. 6 (e.g., for computer-assisted wellcompletion).

Though sometimes described serially in the examples of FIG. 6, one ofordinary skill in the art would recognize that other examples mayreorder the operations, omit one or more operations, and/or execute twoor more operations in parallel using multiple processors or a singleprocessor organized as two or more virtual machines or sub-processors.Moreover, still other examples can implement the operations as one ormore specific interconnected hardware or integrated circuit modules withrelated control and data signals communicated between and through themodules. Thus, any process flow is applicable to software, firmware,hardware, and hybrid implementations.

It is expected that the system range and performance can be extendedwith the various embodiments described herein. Power can often be saved,and accuracy of ranging measurements improved. Signal components may beextracted and converted to pixel colors or intensities and displayed asa function of tool position and azimuth. Assuming the target casingstring is within detection range, it may appear as a bright (or, ifpreferred, a dark) band in the image. The color or brightness of theband may indicate the distance to the casing string, and the position ofthe band indicates the direction to the casing string. Thus, by viewingsuch an image, a driller can determine in a very intuitive mannerwhether the new borehole is drifting from the desired course and he orshe can quickly initiate corrective action. For example, if the bandbecomes dimmer, the driller can steer towards the casing string.Conversely, if the band increases in brightness, the driller can steeraway from the casing string. If the band deviates from its desiredposition directly above or below the casing string, the driller cansteer laterally to re-establish the desired directional relationshipbetween the boreholes.

While the text of this document has been divided into sections, itshould be understood that this has been done as a matter of convenience,and that the embodiments discussed in any one section may form a part ofany or more embodiments described in another section, and vice-versa.Moreover, various embodiments described herein may be combined with eachother, without limitation. Thus, many embodiments may be realized.

Similarly, while some of the above-described embodiments may show onlyone receiver, perhaps in the form of a magnetometer, coil, or telemetryreceiver, one of ordinary skill in the art would realize that a drillstring or downhole tool may include multiple receivers for making thevarious measurements described herein. Examples of various embodimentswill now be listed in a non-limiting fashion, each of which may becombined with one or more of the other embodiments listed.

In some embodiments, a method of range determination comprises firstreceiving three orthogonal components as a first set of field strengthcomponents measured by a sensor when the sensor is located at a firstdepth of a first well. In some embodiments, the method go on to includemoving the sensor to a second depth in the first well; second receivingthree orthogonal components as a second set of field strength componentsmeasured by the sensor when the sensor is located at the second depth;and first determining a first approximate range from the single sensorto a second well, using the first set and the second set of fieldstrength components to determine a field gradient, wherein the secondwell serves as an electromagnetic field source that determines amagnitude of the three orthogonal components during the first receivingand the second receiving, via direct transmission or backscattertransmission.

In some embodiments, the method further comprises moving the sensor to athird depth in the first well; third receiving three orthogonalcomponents as a third set of field strength components measured by thesensor when the sensor is located at the third depth; and seconddetermining a second approximate range from the sensor to the secondwell, using the third set and at least one of the first set or thesecond set of field strength components to determine a confirming fieldgradient, to confirm the first approximate range by comparing the firstapproximate range with the second approximate range.

In some embodiments, the method further comprises selecting a separationbetween the first depth and the second depth to be a first distance(e.g., about 5 m), until a follow drilling phase of drilling operationsbegins.

In some embodiments, the method further comprises selecting theseparation between the first depth and the second depth to be a seconddistance (e.g. about 2.5 m), less than the first distance, when thefollow drilling phase of drilling operations begins, until an interceptdrilling phase or an avoid drilling phase of the drilling operationsbegins.

In some embodiments, the method further comprises selecting theseparation between the first depth and the second depth to be a thirddistance (e.g., about 0.5 m), less than the second distance, when theintercept drilling phase or the avoid drilling phase of the drillingoperations begins.

In some embodiments, a method comprises acquiring a series ofelectromagnetic field strength measurements from a single sensor atmultiple depths in a first well, responsive to an electromagnetic fieldoriginating at a second well, via direct transmission or backscattertransmission. In some embodiments, the method goes on to includedetermining a drilling phase associated with drilling operationsconducted in the first well; selecting a sensor separation depthassociated with the drilling phase; and calculating an approximate rangebetween the first well and the second well, based on the series ofelectromagnetic field strength measurements and the sensor separationdepth.

In some embodiments, the drilling phase is one of identify, follow,intercept, or avoid. In some embodiments, the sensor separation depthassociated with the identify drilling phase is greater than the sensorseparation depth associated with the follow drilling phase, which isgreater than the sensor separation depth associated with the interceptor the avoid drilling phases.

In some embodiments, determining the drilling phase associated withdrilling operations conducted in the first well comprises determiningthe drilling phase in effect at a current sensor depth or a current bitdepth corresponding to a time of calculating the approximate range.

In some embodiments, selecting the sensor separation depth associatedwith the drilling phase comprises selecting the sensor separation depthbased on sensor noise level. In some embodiments, the sensor noise levelis based on lab noise testing or real-time from background measurements.

In some embodiments, selecting the sensor separation depth associatedwith the drilling phase comprises selecting the sensor separation depthbased on desired detection range. In some embodiments, selecting thesensor separation depth associated with the drilling phase comprisesselecting the sensor separation depth based on desired ranging accuracy.

In some embodiments, as shown in FIGS. 1, 4, and 7-8, an apparatuscomprises a down hole tool housing attached to a sensor, the down holehousing to be disposed in a first well; and a range determination moduleRD communicatively coupled to the sensor, the module to determine anapproximate range from the sensor to a second well, using a first set offield strength components and a second set of field strength componentsto determine a field gradient. In some embodiments, the second wellserves as an electromagnetic field source, via direct transmission orbackscatter transmission, and the range determination module RD operatesto determine a magnitude of three orthogonal components forming each ofthe first and the second set of field strength components acquired bythe sensor during a first reception operation at a first depth of thefirst well, and during a second reception operation at a second depth ofthe first well, respectively.

In some embodiments, the sensor comprises a magnetometer.

In some embodiments, the range determination module is to choose aseparation of the first depth and the second depth from availableaccumulated background sensor measurements including at least one ofsensor noise level, selected detection range, or selected rangingaccuracy.

In some embodiments, the down hole tool housing comprises one or more ofa wireline sonde, a bottom hole assembly, a drill collar, a drill stringpipe, or a sub.

In some embodiments, as shown in FIGS. 1, 4, and 7-8, a system comprisesa current source to couple current to one of a target well or a drillingwell; and an apparatus that comprises a down hole tool housing attachedto a sensor, the down hole housing to be disposed in the drilling well,and a range determination module RD communicatively coupled to thesensor. The range determination module RD may operate to determine anapproximate range from the sensor to the target well, using a first setof field strength components and a second set of field strengthcomponents to determine a field gradient, wherein the target well servesas an electromagnetic field source, via direct transmission orbackscatter transmission, that determines a magnitude of threeorthogonal components forming each of the first and the second set offield strength components acquired by the sensor during a firstreception operation at a first depth of the drilling well, and during asecond reception operation at a second depth of the drilling well,respectively.

In some embodiments, the range determination module RD is attached tothe down hole tool housing. In some embodiments, the down hole toolhousing comprises a drill string.

In some embodiments, an apparatus comprises a down hole tool housing(e.g., ranging tool 124) attached to a set of sensors, the down holetool housing comprising one or more of a wireline sonde, a bottom holeassembly, a drill collar, a drill string pipe, or a sub. Someembodiments of this apparatus further comprise a processor (e.g.,computer 140) communicatively coupled to the set of sensors to receiveelectromagnetic signal strength signals from the sensors, and to amemory (e.g., medium 142), the memory having a set of instructionswhich, when executed by the processor, cause the processor to implementany of the methods described herein.

In some embodiments, a system comprises a source of current or voltage(e.g., power supply 148) to electrically couple to a well casing of afirst well or to attach to a first down hole tool housing. Someembodiments of this system further comprise a drill string to bedisposed in a second well and mechanically coupled to a second down holetool housing, the second down hole tool housing attached to a set ofsensors. Some embodiments of this system further comprise a processor(e.g., computer 140) communicatively coupled to the set of sensors toreceive signals representing electromagnetic field strength from thesensors, in response to the source exciting the well casing directly toinitiate direct signal transmission, or indirectly via backscattertransmission, the processor communicatively coupled to a memory (e.g.,medium 142) having a set of instructions which, when executed by theprocessor, cause the processor to implement any of the methods describedherein.

Numerous other variations and modifications will become apparent tothose skilled in the art once the above disclosure is fully appreciated.For example, the foregoing discussion has focused on a logging whiledrilling implementation, but the disclosed techniques would also besuitable for wireline tool implementation (as shown in FIG. 7). It isintended that the following claims be interpreted to embrace all suchvariations and modifications.

In this description, references to “one embodiment” or “an embodiment,”or to “one example” or “an example” mean that the feature being referredto is, or may be, included in at least one embodiment or example of theinvention. Separate references to “an embodiment” or “one embodiment” orto “one example” or “an example” in this description are not intended tonecessarily refer to the same embodiment or example; however, neitherare such embodiments mutually exclusive, unless so stated or as will bereadily apparent to those of ordinary skill in the art having thebenefit of the knowledge provided by this disclosure. Thus, the presentdisclosure includes a variety of combinations and/or integrations of theembodiments and examples described herein, as well as furtherembodiments and examples, as defined within the scope of all claimsbased on this disclosure, as well as all legal equivalents of suchclaims.

The accompanying drawings that form a part hereof, show by way ofillustration, and not of limitation, specific embodiments in which thesubject matter may be practiced. The embodiments illustrated aredescribed in sufficient detail to enable those skilled in the art topractice the teachings disclosed herein. Other embodiments may be usedand derived therefrom, such that structural and logical substitutionsand changes may be made without departing from the scope of thisdisclosure. This Detailed Description, therefore, is not to be taken ina limiting sense, and the scope of various embodiments is defined onlyby the appended claims, along with the full range of equivalents towhich such claims are entitled.

What is claimed is:
 1. A method, comprising: acquiring a series ofelectromagnetic field strength measurements from a sensor at multipledepths in a first well, responsive to an electromagnetic fieldoriginating at a second well, via at least one of a direct transmissionand a backscatter transmission; determining a drilling phase associatedwith drilling operations conducted in the first well; selecting a sensorseparation depth associated with the drilling phase; and calculating anapproximate range between the first well and the second well, based onthe series of electromagnetic field strength measurements and the sensorseparation depth.
 2. The method of claim 1, wherein the drilling phaseis at least one of identify, follow, intercept, and avoid.
 3. The methodof claim 2, wherein the sensor separation depth associated with theidentify drilling phase is greater than the sensor separation depthassociated with the follow drilling phase, which is greater than thesensor separation depth associated with at least one of the interceptthe avoid drilling phases.
 4. The method of claim 1, wherein determiningthe drilling phase associated with drilling operations conducted in thefirst well comprises: determining the drilling phase in effect at atleast one of a current sensor depth and a current bit depthcorresponding to a time of calculating the approximate range.
 5. Themethod of claim 1, wherein selecting the sensor separation depthassociated with the drilling phase comprises: selecting the sensorseparation depth based on sensor noise level.
 6. The method of claim 5,wherein the sensor noise level is based on at least one of lab noisetesting and real-time from background measurements.
 7. The method ofclaim 1, wherein selecting the sensor separation depth associated withthe drilling phase comprises: selecting the sensor separation depthbased on desired detection range.
 8. The method of claim 1, whereinselecting the sensor separation depth associated with the drilling phasecomprises: selecting the sensor separation depth based on desiredranging accuracy.
 9. An apparatus comprising: a downhole tool having asensor, wherein the sensor is to acquire a series of electromagneticfield strength measurements at multiple depths in a first well,responsive to an electromagnetic field originating at a second well, viaat least one of a direct transmission and a backscatter transmission; aprocessor; and a machine-readable medium having program code executableby the processor to cause the processor to, determine a drilling phaseassociated with drilling operations conducted in the first well; selecta sensor separation depth associated with the drilling phase; anddetermine an approximate range between the first well and the secondwell, based on the series of electromagnetic field strength measurementsand the sensor separation depth.
 10. The apparatus of claim 9, whereinthe drilling phase is at least one of identify, follow, intercept, andavoid.
 11. The apparatus of claim 10, wherein the sensor separationdepth associated with the identify drilling phase is greater than thesensor separation depth associated with the follow drilling phase, whichis greater than the sensor separation depth associated with at least oneof the intercept the avoid drilling phases.
 12. The apparatus of claim9, wherein the program code to executable by the processor to cause theprocessor to determine the drilling phase associated with drillingoperations conducted in the first well comprises: program codeexecutable by the processor to cause the processor to determine thedrilling phase in effect at at least one of a current sensor depth and acurrent bit depth corresponding to a time of calculating the approximaterange.
 13. The apparatus of claim 9, wherein the program code toexecutable by the processor to cause the processor to select the sensorseparation depth associated with the drilling phase comprises: programcode executable by the processor to cause the processor to select thesensor separation depth based on sensor noise level.
 14. The apparatusof claim 13, wherein the sensor noise level is based on at least one oflab noise testing and real-time from background measurements.
 15. Theapparatus of claim 9, wherein the program code to executable by theprocessor to cause the processor to select the sensor separation depthassociated with the drilling phase comprises: program code executable bythe processor to cause the processor to select the sensor separationdepth based on desired detection range.
 16. The apparatus of claim 9,wherein the program code to executable by the processor to cause theprocessor to select the sensor separation depth associated with thedrilling phase comprises: program code executable by the processor tocause the processor to select the sensor separation depth based ondesired ranging accuracy.
 17. One or more non-transitorymachine-readable storage media comprising program code executable by aprocessor to cause the processor to: acquire a series of electromagneticfield strength measurements from a sensor at multiple depths in a firstwell, responsive to an electromagnetic field originating at a secondwell, via at least one of a direct transmission and a backscattertransmission; determine a drilling phase associated with drillingoperations conducted in the first well; select a sensor separation depthassociated with the drilling phase; and calculate an approximate rangebetween the first well and the second well, based on the series ofelectromagnetic field strength measurements and the sensor separationdepth.
 18. The one or more non-transitory machine-readable storage mediaof claim 17, wherein the drilling phase is at least one of identify,follow, intercept, and avoid, and wherein the sensor separation depthassociated with the identify drilling phase is greater than the sensorseparation depth associated with the follow drilling phase, which isgreater than the sensor separation depth associated with at least one ofthe intercept the avoid drilling phases.
 19. The one or morenon-transitory machine-readable storage media of claim 1, wherein theprogram code executable by the processor to cause the processor todetermine the drilling phase associated with drilling operationsconducted in the first well comprises: program code executable by theprocessor to cause the processor to determine the drilling phase ineffect at at least one of a current sensor depth and a current bit depthcorresponding to a time of calculating the approximate range.
 20. Theone or more non-transitory machine-readable storage media of claim 1,wherein the program code executable by a processor to cause theprocessor to select the sensor separation depth associated with thedrilling phase comprises: program code executable by a processor tocause the processor to select the sensor separation depth based onsensor noise level, wherein the sensor noise level is based on at leastone of lab noise testing and real-time from background measurements.